Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the oil to reach the surface. In order for oil to be “produced,” that is, travel from the formation to the wellbore, and ultimately to the surface, there must be a sufficiently unimpeded flowpath from the formation to the wellbore. If the formation is naturally “tight”, i.e. has poorly interconnected pores, or has been damaged by the accumulation of mineral or chemical deposits (scales, precipitates, polymer residues, etc.), resulting from prior treatments or from aging of the reservoir, the flowpath is altered and the production is lower than expected.
Stimulation techniques aim at increasing the net permeability of a reservoir. This is typically achieved through the use of fluid pressure to fracture the formation and/or the injection of chemicals through the wellbore and into the formation to react with and dissolve the deposits or the formation, therefore creating alternative flowpaths. This invention is primarily directed to the latter and thus relates to methods to enhance well productivity by dissolving formation minerals (e.g. calcium carbonate), or deposits by techniques known as “matrix acidizing” and “acid fracturing”.
Correct fluid placement plays a critical role in successful well stimulation. Treating fluids must be injected into reservoir zones with lower permeability or higher damage in order to stimulate them. This is true for both matrix acidizing and fracturing. However, injected fluids preferably migrate to higher permeability zones (the path of least resistance) rather than to the lower permeability zones, yet the ones that would most benefit from the treatment.
In response to this problem, numerous, disparate techniques have evolved to achieve more controlled placement of the fluid—i.e., to divert the acid away from naturally high permeability zones and zones already treated, and towards the regions of interest. These techniques can be roughly divided into either mechanical or chemical techniques.
Mechanical techniques include ball sealers (balls dropped into the wellbore and that plug the perforations in the well casing, thus sealing the perforation against fluid entry); packers and bridge plugs, including straddle packers (mechanical devices that plug a portion of the wellbore and thereby inhibit fluid entry into the perforations around that portion of the wellbore); coiled tubing (flexible tubing deployed by a mechanized reel, through which the acid can be delivered to more precise locations within the wellbore); and bullheading or attempting to achieve diversion by pumping the acid at the highest possible pressure—just below the pressure that would actually fracture the formation (described by Paccaloni in SPE 24781).
Chemical diversion techniques can be further divided into ones that chemically modify the wellbore adjacent to portions of the formation for which acid diversion is desired, and ones that modify the acid-containing fluid itself. The first type involve materials that form a reduced-permeability cake on the wellbore face thus reducing the permeability to the acid and diverting it to higher permeability regions. The second type includes foaming agents, emulsifying agents, and gelling agents, which alter the transmissibility of the rock and fluid system.
The primary fluids used in acid treatments are mineral acids such as hydrochloric acid, which was disclosed as the fluid of choice in a patent issued over 100 years ago (U.S. Pat. No. 556,669, Increasing the Flow of Oil Wells, issued to Frasch, H.). At present, hydrochloric acid is still the preferred acid treatment in carbonate formations. For sandstone formations, the preferred fluid is a hydrochloric/hydrofluoric acid mixture. With mineral acids, the major drawback is that they react too quickly and hence penetrate (as unspent acid) into the formation poorly. Second, they are highly corrosive to wellbore tubular components. Organic acids (formic and acetic acid in conventional treatments) are a partial response to the limitations of mineral acids. They are less corrosive and allow greater radial penetration of unspent acid but they also have numerous shortcomings, primarily cost and low reactivity.
Emulsified acid systems and foamed systems are other commercially available responses to the diversion problem, but they are fraught with operational complexity which severely limits their use—e.g., the flow rates of two different fluids, and the bottom hole pressure must be meticulously monitored during treatment.
Gelling agents, especially those not based on crosslinking chemistry but rather upon viscoelastic surfactants, are also used with alternating stages of acid treatment, where the gelling agent preferably decreases the permeability of selected zones and therefore favor the later treatment of the other zones. One system of this type is disclosed in U.S. Pat. No. 4,695,389 (see also, U.S. Pat. No. 4,324,669, and British Patent No. 2,012,830). Another viscoelastic surfactant-based gelling system, also proprietary to Schlumberger, is known as OilSEEKER™, and is disclosed in F. F. Chang, et al., Case Study of a Novel Acid-Diversion Technique in Carbonate Reservoirs, SPE 56529, p. 217 (1999).
Self diverting systems, that allow one-step treatment, have also been proposed for instance in U.S. Pat. No. 6,399,546, with a diverter contained within the acid-containing fluid.
These numerous techniques proceed by completely different ways such as modification of the wellbore interface or modification of the acid-containing fluid itself. They are usually very sensitive to any feature in the reservoir that will conduct these diverting agents out of the target zone, for instance a natural fracture and they may actually damage the formation and create rather than solve matrix damages if used improperly. The design of a matrix treatment is consequently very challenging.
Hence, the effectiveness of a treatment, and more particularly the diversion effectiveness, is very difficult to evaluate. During fracture treatments, analysis of surface treating pressures can be used in some cases to analyze it; however, this method does not work for acidizing since pressure surges at the surface may not be correlated to changes in flow profile downhole (see C. W. Crowe, Evaluation of Oil Soluble Resin Mixtures as Diverting Agents for Matrix Acidizing, SPE 3505, 1971 and J. W. Burman, B. E. Hall, Foam as Diverting Technique for Matrix Sandstone Stimulation, SPE 15575, 1986).
As a result methods for determining actual fluid placement have mainly been limited to post treatment analysis. Some of the methods used have been radioactive tracers, comparison of pre-and post-treatment flowmeter logs, and pre-and post-treatment temperature logs.
One main disadvantage of using post treatment analysis to determine fluid entry is that nothing can be done to change things once the treatment is done. If fluid entry could be monitored during the treatment, changes could possibly be made to the treatment that would change the fluid profile along the wellbore. Therefore, real-time monitoring of fluid entry into the reservoir would be very useful information to have during treatment.